One of the most robust and dependable pieces of equipment in the oil extraction industry, commonly referred to as oil pumping, is the sucker rod pump. The sucker rod pumping system described is by far the most widely used of any artificial lift system. To simply describe the operation of the sucker rod pump is to describe the pumping cycle. Typically, a plunger inside a pump barrel of the sucker rod pump starts the upstroke actuated by the sucker rod, which in turn is actuated by a pumping unit on the surface. The weight of the liquid above the plunger will cause a one-way check valve, known as a “traveling valve,” to close. Typically, the traveling valve is part of the plunger and, thus, travels with movement of the plunger. The upward motion of the plunger (“upstroke”) will cause a reduction in pressure below the plunger in the lower portion of the pump. The pressure of the standing column of oil outside the pump will cause the oil to flow into a void in the lower portion of the pump created by the upstroke through another one-way check valve, known as a “standing valve.”
As the motion of the plunger is reversed and the plunger starts downward (“downstroke”), the standing valve becomes closed. The pressure below the plunger increases and the traveling valve is opened. The fluid that previously entered through the standing valve flows upward through the traveling valve and into an upper portion of the pump above the plunger. On the next upstroke, the plunger displaces this fluid into the tubing above the pump. On successive cycles, an increment of fluid is displaced into the tubing, and eventually is discharged at the surface for further processing.
FIG. 1 is a schematic diagram of a prior art sucker rod pumping system. The figure illustrates one typical system by which produced fluids in a well are currently pumped from a subsurface depth of a well to the surface. The well generally includes a casing 12 installed into a well bore drilled into the earth and a conduit 15, generally termed “tubing,” inserted into the casing for flowing fluids therethrough. One or more perforations 13 are formed in the casing to allow production fluids to enter the interior of the casing and be pumped to the surface. A sucker rod pump 30A, particularly an inlet of the pump, is installed below a fluid level 20 of the well so that fluid can enter the sucker rod pump and be pumped to the surface of the well through outlet 41 for further processing. A rod 24A, called the “thrusting rod,” protrudes from the sucker rod pump axis.
A pumping unit 3 pivots rotationally, as shown by the curved motion arrows. This rotational pivoting action is leveraged into an up-and-down motion via one or more cables 6 from the pumping unit 3. The cables 6 are connected to a polish rod, which is connected to at least one sucker rod 9. An assembly of sucker rods creates a sucker rod string of a certain length. The up-and-down motion of the pumping unit is transmitted down the well through the sucker rods 9 to the sucker rod pump 30A.
As can be seen within the cutaway outline 18, the sucker rod 9 transmits its thrusting action via a joiner 21 to the rod 24A of the sucker rod pump 30A. The sucker rod is prone to failure. The failure can be attributed to a number of causes, but the repair of the rod string to return the well to operational status presents high costs to the operator. Not only is the cost of the equipment to be repaired significant, but the well servicing rig to pull and repair the sucker rod string represents a large portion of the repair. Further, when sucker rod wear on the interior of the tubing creates a leak in the tubing, that tubing must be repaired and tested to ensure integrity. The well servicing costs associated with sucker rod breaks and tubing leaks are a large part of the significant costs associated with rod pumped well failures.
A plunger (not shown) is coupled to the rod 24A inside the sucker rod pump 30A. The plunger has one or more one-way check valves (not shown), commonly called “traveling valves”. As the rod 24A drives the plunger down in the downstroke, well fluid flows through these check valves. Once having flowed through these check valves, the well fluid is now in or on the top of the plunger. When the rod 24A downward motion reverses into an upstroke, the plunger lifts the well fluid up through a second set of one-way check valves 36, commonly called “standing valves,” into the tubing 15. Also, as the plunger rises, well fluid is drawn into the lower part of the sucker rod pump via the inlet holes 33A. This same well fluid will move above the plunger on the plunger's downstroke.
Once well fluid is in the tubing 15, the one-way check valves 36 prevent the well fluid from returning into the sucker rod pump 30A. Additional well fluid is pumped into the tubing 15 with repeated cycles. With each new cycle, well fluid 39 is raised higher, eventually flowing to the surface and out the outlet 41 for further processing. This is the basic description of the prior art as to how well fluid is currently pumped from an oil well.
When the proper reciprocating linear motion is provided, this method of using a rod pump to pump fluid is dependable and has longevity. Longevity is important for components installed in an oil well, because the component may have to be brought to the surface from depths that may exceed a mile. Such operations are typically very costly from the service and from downtime in production.
Presently, the major disadvantage of a sucker rod pump system is that the linear force to drive the pump is from sucker rods emanating from the surface, which is often over a mile above the sucker rod pumps. These rods can weigh from one to three pounds per foot of depth and can easily weigh upwards of eight tons in many applications. Importantly, these tons of rods must not only be continuously supported, but their direction must be reversed for every stroke of fluid pumped.
The procedure is inefficient and requires a substantial energy input due to the frictional losses of the rods rubbing against the tubing in which they are encased, and the bearings of the pumping unit that have to rotate while under this constant support pressure. Also, the pumping unit, required to generate the reciprocating motion, is expensive and dangerous. Environmentalist groups claim that the pumping unit, which stands 25-40 feet high, is an eye sore. Further, surface pumping equipment, such as the pumping unit 3, can present problems in agricultural areas, because of the surface area required as well as vertical obstacles in farmlands where surface ground traversing irrigation systems are used.
There are other methods of artificial lift such as submersible centrifugal pumps, progressive cavity pumps, gas lift, and hydraulic pumping. The submersible centrifugal pumps are normally used for high volume applications, where the volume to be lifted exceeds rod pumping capabilities. These electrically driven centrifugal pumps utilize a series of impellers, which converts the centrifugal force on the fluid into pressure. Progressive cavity pumps are positive displacement pumps that can be driven by shafts rotated by motors on the surface, while some are actuated by submersible motors. Gas lift pumping utilizes natural gas as a lift mechanism either through continuous flow, intermittent flow, or plunger lift methods. Hydraulic pumping uses pumps on the surface to pressurize liquids, such as oil, to activate the downhole pump. Each type has its applications, but also problems unique to each type.
One significant problem that these other artificial lift technologies generally encounter is the high capital cost and excessive operating expenses when lifting low volume producing wells. This technology is unsuitable for most wells presently in operation in the United States, which produce less than 50 barrels of oil and water per day. Another problem is the life of the equipment or the duration of service without major maintenance, which, while quite short, may be acceptable for high volume applications that can justify expensive maintenance.
Another design idea has been proposed that includes a motor down in the well near the fluid level, where the motor can turn a threaded shaft upon which a nut-like assembly is attached. As the threaded shaft rotates, the nut-like assembly moves linearly up the shaft. This nut-like assembly is connected to the input rod of the rod pump. The direction of rotation of the threaded shaft is reversed when the chamber of the rod pump is at its largest. Then, the nut-like assembly will move down the threaded shaft, forcing the input rod back into the rod pump and the chamber size will shrink, thereby pumping the fluid. The motor can continue to alternate reversing its rotation to reverse the rotation of threaded shaft to continue to pump the fluid.
While the nut on thread process may be theoretically possible, there are several drawbacks in its practical implementation. First, this mechanism wears out relatively quickly, far short of the required number of reciprocations for a standard well, even using ball bearings in the threaded nuts. The second failing is that a motor which can reverse direction is inherently less efficient, more expensive, and more maintenance prone. The goal of a low maintenance system over the life of the well is compromised.
Thus, there remains a need for an improved pumping system that targets low volume applications with low capital investment and long life between repairs.